Electrically operated drilling method

ABSTRACT

A method of drilling a borehole from a selected location in an existing wellbore ( 1 ) penetrating subterranean earth formation having at least one hydrocarbon bearing zone ( 3 ) wherein the existing wellbore is provided with a casing ( 4 ) and a hydrocarbon fluid production conduit ( 6 ) is arranged in the existing wellbore in sealing relationship with the wall of the casing, the method comprising: passing a remotely controlled electrically operated drilling device ( 12 ) from the surface through the hydrocarbon fluid production conduit to the selected location in the existing wellbore; operating the drilling device such that cutting surfaces on the drilling device drill the borehole from the selected location in the existing wellbore thereby generating drill cuttings wherein during operation of the drilling device, a first stream of produced fluid flows directly to the surface through the hydrocarbon fluid production conduit and a second stream of produced fluid is pumped over the cutting surfaces of the drilling device via a remotely controlled electrically operated downhole pumping means and the drill cuttings are transported away from the drilling device entrained in the second stream of produced fluid.

The present invention relates to a method of drilling a borehole from aselected location in an existing wellbore penetrating a subterraneanhydrocarbon fluid bearing formation using a remotely controlledelectrically operated drilling device wherein the drilling device isintroduced into the existing wellbore through a hydrocarbon fluidproduction conduit and produced fluid, for example produced liquidhydrocarbon and/or produced water is pumped over the cutting surfaces ofthe drilling device using a remotely controlled electrically operatedpumping means to cool the cutting surfaces and to transport drillcuttings away from the drilling device.

In conventional methods of wellbore drilling a drill string including adrill bit at its lower end is rotated in the wellbore while drillingfluid is pumped through a longitudinal passage in the drill string,which drilling fluid returns to surface via the annular space betweenthe drill string and the wellbore wall. When drilling through an earthlayer not containing a fluid, the weight and the pumping rate of thedrilling fluid are selected so that the pressure at the wellbore wall iskept between a lower level at which the wellbore becomes unstable and anupper level at which the wellbore wall is fractured. When the wellboreis drilled through a hydrocarbon fluid containing zone the drillingfluid pressure should moreover be above the pressure at whichhydrocarbon fluid starts flowing into the wellbore, and below thepressure at which undesired invasion of drilling fluid into theformation occurs. These requirements impose certain restrictions to thedrilling process, and particularly to the length of the wellboreintervals at which casing is to be installed in the wellbore. Forexample, if the drilling fluid pressure at the wellbore bottom is justbelow the upper limit at which undesired drilling fluid invasion intothe formation occurs, the drilling fluid pressure at the top of theopen-hole wellbore interval can be close to the lower limit at whichhydrocarbon fluid influx occurs. The maximum allowable length of theopen-hole interval depends on the specific weight of the drilling fluid,the hydrocarbon fluid pressure in the formation, and the height of thedrilling fluid column.

Furthermore, it has been practised to drill through a hydrocarbon fluidbearing zone at wellbore pressures below the formation fluid pressure, amethodology commonly referred to as under-balanced drilling. Duringunder-balanced drilling hydrocarbon fluid flows into the wellbore, andconsequently the drilling equipment at the surface has to be designed tohandle such inflow. Moreover, special measures must be taken to controlthe fluid pressure in the wellbore during the drilling process.

U.S. Pat. No. 6,305,469 relates to a method of creating a wellbore in anearth formation, the wellbore including a first wellbore section and asecond wellbore section penetrating a hydrocarbon fluid bearing zone ofthe earth formation, the method comprising drilling the first wellboresection; arranging a remotely controlled drilling device at a selectedlocation in the first wellbore section, from which selected location thesecond wellbore section is to be drilled; arranging a hydrocarbon fluidproduction tubing in the first wellbore section in sealing relationshipwith the wellbore wall, the tubing being provided with fluid flowcontrol means and a fluid inlet in fluid communication with saidselected location; operating the drilling device to drill the newwellbore section whereby during drilling of the drilling device throughthe hydrocarbon fluid bearing zone, flow of hydrocarbon fluid from thesecond wellbore section into the production tubing is controlled by thefluid flow control means. By drilling through the hydrocarbon fluidbearing zone using the remotely controlled drilling device, anddischarging any hydrocarbon fluid flowing into the wellbore through theproduction tubing, it is achieved that the wellbore pressure no longerneeds to be above the formation fluid pressure. The wellbore pressure iscontrolled by controlling the fluid flow control means. Furthermore, nospecial measures are necessary for the drilling equipment to handlehydrocarbon fluid production during drilling. In case the secondwellbore is to be drilled through one or more layers from which nohydrocarbon fluid flows into the wellbore, it is preferred that thedrilling device comprises a pump system having an inlet arranged toallow drill cuttings resulting from the drilling action of the drillingdevice to flow into the inlet, and an outlet arranged to discharge saiddrill cuttings into the wellbore behind the drilling device. Suitablysaid outlet is arranged a selected distance behind the drilling deviceand at a location in the wellbore section where a fluid is circulatedthrough the wellbore, which fluid entrains the drill cuttings andtransports the drill cuttings to surface. The second wellbore sectioncan be a continuation of the existing wellbore, or can be a side-trackor lateral well (i.e. a branch) of the existing wellbore. It is taughtthat the drilling device is releasably connected to the lower end of ahydrocarbon production tubing by a suitable connecting device. Thehydrocarbon production tubing is then lowered into the casing until thedrilling device is near the bottom of the first wellbore sectionwhereafter the production tubing is fixed to the casing by inflating apacker which seals the annular space formed between the productiontubing and the casing. Accordingly, there remains a need for a remotelycontrolled drilling device that uses fluid produced from the formationto transport drill cuttings away from the cutting surfaces of the devicewherein the device is capable of being passed from the surface to aselected location in an existing wellbore without having to pull thehydrocarbon fluid production tubing from the wellbore.

Thus, the present invention provides a method of drilling a boreholefrom a selected location in an existing wellbore penetrating asubterranean earth formation having at least one hydrocarbon fluidbearing zone wherein the existing wellbore is provided with a casing anda hydrocarbon fluid production conduit is arranged in the wellbore insealing relationship with the wall of the casing, the method comprising:

-   passing a remotely controlled electrically operated drilling device    from the surface through the hydrocarbon fluid production conduit to    the selected location in the existing wellbore;-   operating the drilling device such that cutting surfaces on the    drilling device drill the borehole from the selected location in the    existing wellbore thereby generating drill cuttings wherein during    operation of the drilling device, a first stream of produced fluid    flows directly to the surface through the hydrocarbon fluid    production conduit and a second stream of produced fluid is pumped    over the cutting surfaces of the drilling device via a remotely    controlled electrically operated downhole pumping means and the    drill cuttings are transported away from the drilling device    entrained in the second stream of produced fluid.

By “produced fluid” is meant produced liquid hydrocarbons and/orproduced water, preferably produced liquid hydrocarbons.

An advantage of the process of the present invention is that hydrocarbonfluid may to be produced from the existing wellbore during drilling ofthe borehole from the selected location. A further advantage of theprocess of the present invention is that the second stream of producedfluid cools the cutting surfaces of the drilling device in addition totransporting the drill cuttings away from the cutting surfaces.

Yet a further advantage of the present invention is that the method maybe used to drill a new wellbore section without having to pull theproduction conduit from the existing wellbore. It is envisaged thatfluid may have been produced from the hydrocarbon fluid bearing zone ofthe formation prior to passing the remotely controlled electricallyoperating drilling device through the production conduit to the selectedlocation in the wellbore. However, the method of the present inventionmay also be used where the existing wellbore has been drilled to aselected location immediately above the hydrocarbon fluid bearing zoneof the formation and the new borehole extends the existing wellbore intosaid hydrocarbon fluid bearing zone. Thus, the new wellbore section maybe:

-   -   (a) a wellbore extending into the hydrocarbon fluid bearing zone        of the formation from a selected location immediately above said        zone;    -   (b) a continuation of an existing wellbore that penetrates the        hydrocarbon fluid bearing zone of the formation    -   (c) a side-track well from a selected location in the production        tubing or a selected location in the existing wellbore below the        production tubing;    -   (d) a lateral well from a selected location in the production        tubing and/or a selected location in the existing wellbore below        the production tubing; and    -   (e) a lateral exploration well from a selected location in the        production tubing and/or a selected location in the existing        wellbore below the production tubing.

By “side-track well” is meant a branch of the existing wellbore wherethe existing wellbore no longer produces hydrocarbon fluid. Thus, theexisting wellbore is sealed below the selected location from which theside-track well is to be drilled, for example, with cement. By “lateralwell” is meant a branch of the existing wellbore where the existingwellbore continues to produce hydrocarbon fluid. Suitably, a pluralityof lateral wells may be drilled from the existing wellbore. The lateralwells may be drilled from same location in the existing wellbore i.e. indifferent radial directions and/or from different locations in theexisting wellbore i.e. at different depths. By “lateral explorationwell” is meant a well that is drilled to explore the formation matrixand formation fluids at a distance from the existing wellbore, asdescribed in more detail below.

Suitably, the casing may be run from the surface to the bottom of theexisting wellbore. Alternatively, the casing may be run from the surfaceinto the upper section of the existing wellbore with the lower sectionof the existing wellbore comprising a barefoot or open-hole completion.Where the selected location in the cased wellbore lies below theproduction conduit, the borehole formed by the drilling device may be awindow in the casing. It is also envisaged that the selected location inthe cased wellbore may lie within the production conduit, in which casethe borehole formed by the drilling device may be a window through theproduction conduit and through the casing of the wellbore. The casing ofthe existing wellbore at the selected location may be formed from metalin which case the cutting surfaces on the drilling device should becapable of milling a window through the casing by grinding or cuttingthe metal. Thus, the term “drilling device” as used herein encompassesmilling devices and the term “drill” encompasses “mill”. Alternatively,the casing at the selected location in the existing wellbore may beformed from a friable alloy or composite material such that the windowmay be milled using a drilling device fitted with a conventional drillbit.

Advantageously, the method of the present invention may also be used todrill through mineral scale that has been deposited on the wall of theexisting wellbore and optionally such mineral scale deposited on thewall of the hydrocarbon fluid production conduit thereby enlarging theavailable borehole in the existing wellbore and, optionally, theavailable borehole in the production conduit.

Additionally, the method of the present invention may be used to form aperforation tunnel in the casing and cement of the existing wellbore, toremove debris blocking a perforation tunnel or to enlarge a perforationtunnel in the existing wellbore. Suitably, the drilling device employedfor forming a new perforation tunnel or for clearing or enlarging anexisting perforation tunnel is a micro-drilling device having cuttingsurfaces sized to form a borehole having a diameter of from 0.2 to 3inches.

Preferably, the borehole formed by the drilling device in the existingwellbore comprises a new section of wellbore.

Thus, according to a particularly preferred embodiment of the presentinvention there is provided a method of drilling a section of wellborefrom a selected location in an existing wellbore penetrating asubterranean earth formation having at least one hydrocarbon fluidbearing zone wherein the existing wellbore is provided with a casing anda hydrocarbon fluid production conduit is arranged in the wellbore insealing relationship with the wall of the casing, the method comprising:

-   passing a remotely controlled electrically operated drilling device    from the surface through the hydrocarbon fluid production conduit to    a selected location in the existing wellbore, from which selected    location the section of wellbore is to be drilled;-   operating the drilling device such that cutting surfaces on the    drilling device drill the section of wellbore from the selected    location in the existing wellbore thereby generating drill cuttings    wherein during operation of the drilling device, a first stream of    produced fluid flows directly to the surface through the hydrocarbon    fluid production conduit and a second stream of produced fluid is    pumped over the cutting surfaces of the drilling device via a    remotely controlled electrically operated downhole pumping means and    the drill cuttings are transported away from the drilling device    entrained in the second stream of produced fluid.

An advantage of this preferred embodiment of the present invention isthat hydrocarbon fluid may to be produced from the hydrocarbon fluidbearing zone into the existing wellbore during drilling of the newsection of wellbore. A further advantage of this preferred embodiment ofthe present invention is that hydrocarbon fluid may flow from thehydrocarbon fluid bearing zone into the new section of wellbore duringthe drilling operation.

Preferably, the first stream of produced fluid comprises a major portionof the fluid produced from the hydrocarbon fluid bearing zone of theformation. As discussed above, the produced fluid may comprise producedliquid hydrocarbons and/or produced water, preferably, produced liquidhydrocarbons.

The pressure of the hydrocarbon-bearing zone of the subterraneanformation may be sufficiently high that the first stream of producedfluid flows to the surface through the hydrocarbon fluid productionconduit by means of natural energy. However, the method of the presentinvention is also suitable for use in artificially lifted wells.Generally, the entrained cuttings stream may be diluted into the firststream of produced fluid with the cuttings being transported to thesurface together with the produced fluid. The cuttings may be removedfrom the produced fluid at a hydrocarbon fluid processing plant usingconventional cuttings separation techniques, for example, using ahydrocyclone or other means for separating solids from a fluid stream.However, it is also envisaged that at least a portion of the cuttingsmay disentrain from the produced fluid and may be deposited in the rathole of the existing wellbore. Parameters affecting disentrainment ofthe cuttings include the flow rate of the first stream of producedfluid, the viscosity of the produced fluid, the density of the cuttingsand their size and shape.

Suitably, the drilling device is passed from the surface to the selectedlocation in the existing wellbore suspended on a cable. Preferably, thecable is formed from reinforced steel. The cable may be connected to thedrilling device by means of a connector, preferably, a releasableconnector. Preferably, the cable encases one or more wires or segmentedconductors for transmitting electricity or electrical signals(hereinafter “conventional cable”). The cable may also be a modified“conventional cable” comprising a core of an insulation material havingat least one electrical conductor wire or segmented conductor embeddedtherein, an intermediate fluid barrier layer and an outer flexibleprotective sheath. Suitably, the intermediate fluid barrier layer iscomprised of steel. Suitably, the outer protective sheath is steelbraiding. Preferably, the electrical conductor wire(s) and/or segmentedconductor(s) embedded in the core of insulation material is coated withan electrical insulation material.

Preferably, the drilling device is provided with an electricallyoperated steering means, for example, a steerable joint, which is usedto adjust the trajectory of the new wellbore section as it is beingdrilled. This steering means is electrically connected to equipment atthe surface via an electrical conductor wire or a segmented conductorembedded in the cable.

Preferably, the existing wellbore has an inner diameter of 5 to 10inches. Preferably, the production conduit has an inner diameter of 2.5to 8 inches, more preferably 3.5 to 6 inches. Suitably, the drillingdevice has a maximum outer diameter smaller than the inner diameter ofthe production conduit thereby allowing the drilling device to passthrough the production conduit and out into the existing wellbore.Preferably, the maximum outer diameter of the drilling device is atleast 0.5 inches, more preferably, at least 1 inch less than the innerdiameter of the production conduit. The cutting surfaces on the drillingdevice may be sized to form a new wellbore section having a diameterthat is less than the inner diameter of the production conduit, forexample, a diameter of 3 to 5 inches. However, the drilling device ispreferably provided with expandable cutting surfaces, for example, anexpandable drill bit thereby allowing the wellbore that is drilled fromthe selected location to be of larger diameter than the inner diameterof the production conduit.

Preferably, the drilling device has a first drill bit located at thelower end thereof and a second drill bit located at the upper endthereof. This is advantageous in that the second drill bit may be usedto remove debris when withdrawing the drilling device from the wellbore.

Suitably, the drilling device may be provided with formation evaluationsensors which are electrically connected to recording equipment at thesurface via the electrical conductor wire(s) or segmented conductor(s)in the cable. Suitably, the sensors are located in proximity to thecutting surfaces on the drilling device.

Optionally, the conventional cable or modified cable from which thedrilling device is suspended may be provided with a plurality of sensorsarranged along the length thereof. Preferably, the sensors are arrangedat intervals of from 5 to 20 feet along the length of the cable. This isadvantageous when the drilling device is used to drill a lateral“exploration” well as the sensors may be used to receive and transmitdata relating to the nature of the formation rock matrix and theproperties of the formation fluids at a distance from the existingwellbore. The data may be continuously or intermittently sent to thesurface via the electrical conductor wire(s) and/or segmentedconductor(s) embedded in the conventional cable or modified conventionalcable. The lateral “exploration” well may be drilled to a distance offrom 10 to 10,000 feet, typically up to 2,000 feet from the existingwellbore. The drilling device and associated cable may be left in placein the lateral “exploration well” for at least a day, preferably atleast a week, or may be permanently installed in the lateral“exploration” well. Suitably, a plurality of expandable packers arearranged at intervals along the length of the cable. The expandablepackers may be used to isolate one of more sections of the lateral“exploration” well thereby allowing data to be transmitted via the cableto the surface relating to the formation conditions in the sealedsection(s) of the lateral “exploration” wellbore. Once sufficientinformation has been obtained from the sealed section of the lateral“exploration” wellbore, the expandable packers may be retracted and atleast one new section of the lateral “exploration” wellbore may beisolated and further data may be transmitted to the surface.

Where the borehole formed by the drilling device comprises a new sectionof wellbore, it is preferred that the cable from which the drillingdevice is suspended lies within a length of tubing. Suitably, theinterior of the tubing is in fluid communication with a fluid passage inthe drilling device. The term “passage” as used herein means a conduitor channel for transporting fluid through the drilling device. Suitably,the drilling device is attached either directly or indirectly to thetubing. The tubing extends from the drilling device along at least alower section of the cable. Preferably, the tubing extends into thehydrocarbon fluid production conduit. Suitably, the length of the tubingis at least as long as the desired length of the new wellbore section.It is envisaged that sensors may be located along the section of cablethat lies within the tubing and/or along the outside of the tubing.Where sensors are located on the outside of the tubing, the sensors maybe in communication with the electrical conductor wire(s) and/orsegmented conductor(s) of the cable via electromagnetic means.

The tubing has an outer diameter smaller than the inner diameter of theproduction conduit thereby allowing the tubing to pass through theproduction conduit. As discussed above, the production conduitpreferably has an inner diameter of 2.5 to 8 inches, more preferably 3.5to 6 inches. Preferably, the tubing has an outer diameter that is atleast 0.5 inch, more preferably at least 1 inch less than the innerdiameter of the production conduit. Typically, the tubing has an outerdiameter in the range 2 to 5 inches.

Advantageously, the second stream of produced fluid may be passed to thedrilling device through the annulus formed between the tubing and thewall of the new section of wellbore and the cuttings entrained in thesecond stream of produced fluid (hereinafter “entrained cuttingsstream”) may be transported away from the drilling device through theinterior of the tubing (“reverse circulation” mode). Suitably, thetubing may extend to the surface so that the entrained cuttings streammay be reverse circulated out of the wellbore.

Typically, the tubing may be steel tubing or plastic tubing.

Where the tubing is steel tubing, optionally a housing, preferably acylindrical housing, may be attached either directly or indirectly tothe end of the steel tubing remote from the drilling device, forexample, via a releasable connector. Thus, the drilling device may beattached to a first end of the steel tubing and the housing to a secondend of the steel tubing. For avoidance of doubt, the cable passesthrough the housing and through the steel tubing to the drilling device.An electric motor may be located in the housing and electricity maytransmitted to the motor via an electrical conductor wire or segmentedconductor encased in the cable. The electric motor may be used toactuate a means for rotating the steel tubing and hence the drillingdevice connected thereto. Preferably, the housing is provided withelectrically operated traction means which may be used to advance thesteel tubing and hence the drilling device through the new wellboresection as it is being drilled. Electricity is transmitted to thetraction means via an electrical conductor wire or segmented conductorencased in the cable. Suitably, the traction means comprises wheels orpads which engage with and move over the wall of the hydrocarbon fluidproduction conduit.

As an alternative or in addition to rotating the steel tubing, thedrilling device may be provided with an electric motor for actuating ameans for driving a drill bit. Typically, the means for driving thedrill bit may be a rotor. As discussed above, a drill bit may be locatedat the lower end of the drilling device and optionally at the upper endthereof. It is envisaged that the upper and lower drill bits may beprovided with dedicated electric motors. Alternatively, a singleelectrical motor may drive both drill bits. Suitably, the electricmotor(s) is located in a housing of the drilling device, preferably acylindrical housing. Electricity is transmitted to the motor(s) via anelectrical conductor wire or segmented conductor encased in the cable.The housing of the drilling device may also be provided with anelectrically operated traction means which is used to advance thedrilling device and steel tubing through the new wellbore section as itis being drilled and also to take up the reactive torque generated bythe means for driving the drill bit. Electricity is transmitted to thetraction means via an electrical conductor wire or segmented conductorencased in the cable. Suitably, the traction means comprises wheels orpads which engage with and move over the wall of the new wellboresection. It is envisaged that the drilling device may be advancedthrough the new wellbore section using both the traction means providedon the optional housing attached to the second end of the steel tubingand the tractions means provided on the housing of the drilling device.

As discussed above, the second stream of produced fluid may be drawn tothe drilling device through the annulus formed between the steel tubingand the wall of the new section of wellbore and the entrained cuttingsstream may be transported away from the drilling device through theinterior of the steel tubing (“reverse circulation” mode). Accordingly,the housing of the drilling device is preferably provided with at leastone inlet to a first passage in the housing. This first passage is influid communication with a second passage and a third passage in thehousing of the drilling device. The second passage has an outlet that isin fluid communication with the interior of the steel tubing while thethird passage has an outlet in close proximity to the cutting surfacesof the drilling device. Typically, the second stream of produced fluidis drawn through the inlet(s) of the first passage via a pumping means,for example, a suction pump, located in the housing. The second streamof produced fluid is then divided into a first divided fluid stream andsecond divided fluid stream. The first divided fluid stream flowsthrough the second passage in the housing of the drilling device andinto the interior of the steel tubing while the second divided fluidstream flows through the third passage in the housing of the drillingdevice and out over the cutting surfaces such that the drill cuttingsare entrained therein. The resulting entrained cuttings stream is thenpassed over the outside of the drilling device before being recycledthrough the inlet(s) of the first passage in the housing of the drillingdevice. The majority of the cuttings pass into the interior of the steeltubing entrained in the first divided fluid stream. The first dividedfluid stream containing the entrained cuttings is discharged from thesecond end of the steel tubing that is remote from the drilling device,preferably into the hydrocarbon fluid production conduit where thecuttings are diluted into the first stream of produced fluid that flowsdirectly to the surface through the hydrocarbon fluid productionconduit.

Alternatively, the second stream of produced fluid may be pumped to thedrilling device through the interior of the steel tubing while theentrained cuttings stream may be transported away from the drillingdevice through the annulus formed between the steel tubing and the wallof the new wellbore section (“conventional circulation” mode).Preferably, the second stream of produced fluid flows from the steeltubing through a passage in the drilling device and out over the cuttingsurfaces where the produced fluid cools the cutting surfaces and thecuttings become entrained in the produced fluid. The resulting entrainedcuttings stream is then transported away from the cutting surfaces overthe outside of the drilling device and through the annulus formedbetween the steel tubing and the wall of the new section of wellbore. Itis envisaged the produced fluid flowing from the hydrocarbon fluidbearing zone of the formation into the annulus may assist intransporting the cuttings through the annulus. The second stream ofproduced fluid may be pumped to the drilling device through the steeltubing via a remotely controlled electrically operated downhole pumpingmeans, for example, a suction pump, located in the housing of thedrilling device and/or via a remotely controlled electrically operatedpumping means located in the optional housing attached to the second endof the steel tubing that is remote from the drilling device. Preferably,the inlet to the second end of the steel tubing is provided with afilter to prevent any cuttings from being recycled to the drillingdevice.

The steel tubing may be provided with at least one radially expandablepacker, for example, 2 or 3 radially expandable packers, therebyallowing the steel tubing to form a lining for the new wellbore section.When the packer(s) is in its non-expanded state, the steel tubingtogether with the packer(s) should be capable of being passed throughthe hydrocarbon fluid production conduit to the selected location of thewellbore from which the new wellbore section is to be drilled. Also, theradially expandable packer(s) should not interfere with the flow offluid, during the drilling operation, through the annulus formed betweenthe steel tubing and the wall of the new wellbore section. Once thedrilling operation is complete, the steel tubing may be locked in placein the new wellbore section by expanding the radially expandablepacker(s). Suitably, the steel tubing extends into the hydrocarbon fluidproduction conduit. Preferably, the upper section of the steel tubingthat extends into the production conduit is provided with at least oneradially expandable packer(s) such that expansion of the packer(s) sealsthe annulus formed between the steel tubing and the hydrocarbon fluidproduction conduit. As an alternative to using expandable packer(s), atleast a section of the steel tubing may be provided with an outercoating of a rubber that is swellable when exposed to produced fluids,in particular, hydrocarbon fluids so that the swollen rubber coatingforms a seal between the steel tubing and the wall of the new wellboresection. The steel tubing is then perforated to allow produced fluid toflow from the hydrocarbon-bearing zone of the formation into theinterior of the steel tubing and into the production conduit.

Alternatively, the steel tubing may be expandable steel tubing. When inits non-expanded state, the steel tubing should be capable of beingpassed down through the hydrocarbon fluid production conduit of theexisting wellbore to the selected location in the existing wellbore fromwhich the new well bore section is to be drilled. Once the drillingoperation is complete, the steel tubing may be expanded to form a liningfor the new well bore section. Suitably, the expandable steel tubingextends into the hydrocarbon fluid production conduit. The length of thesteel tubing which extends into the hydrocarbon fluid production conduitmay be expanded against the wall of the production conduit therebyeliminating the requirement for an expandable packer. The steel tubingis then perforated to allow the produced fluid to flow from thehydrocarbon-bearing zone of the formation into the interior of theexpanded steel tubing and into the hydrocarbon fluid production conduit.The steel tubing may be expanded by: locking the drilling device inplace in the wellbore, for example, using radially extendible grippingmeans positioned on the housing of the drilling device; detaching thedrilling device from the cable and steel tubing; pulling the cable tothe surface through the hydrocarbon fluid production conduit andattaching a conventional expansion tool thereto, for example, anexpandable mandrel; inserting the expansion tool into the wellborethrough the hydrocarbon fluid production conduit and through the steeltubing; and drawing the expansion tool back through the steel tubing toexpand the tubing. The drilling device may then be retrieved from thewellbore by: reattaching the cable to the drilling device; retractingthe radially extendible gripping means; and pulling the cable anddrilling device from the wellbore through the expanded steel tubing andthe hydrocarbon fluid production conduit and/or actuating theelectrically operatable traction means thereby moving the drillingdevice through the expanded steel tubing and the production conduit.Alternatively, an electrically operated rotatable expansion tool havingradially extendible members may be attached either directly orindirectly to the drilling device, at the upper end thereof. Electricitymay be transmitted to the rotatable expansion tool via an electricalconductor wire or segmented conductor encased in the cable. A suitablerotatable expansion tool is as described in U.S. patent application No.2001/0045284 which is herein incorporated by reference. Suitably, thisrotatable expansion tool may be adapted by providing a fluid passagetherethrough such that, during the drilling operation, the interior ofthe steel tubing is in fluid communication with a fluid passage in thedrilling device. The rotatable expansion tool may be releasably attachedto the expandable steel tubing, for example, via an electricallyoperated latch means. After completion of drilling of the new wellboresection, the rotatable expansion tool is released from the steel tubing.The rotatable expansion tool is then operated to expand the steel tubingby drawing the expansion tool and the associated drilling device throughthe steel tubing while simultaneously rotating the expansion tool andextending the radially extendible members. Following expansion of thesteel tubing, the rotatable expansion tool and the associated drillingdevice may be retrieved from the wellbore through the hydrocarbon fluidproduction conduit by retracting the radially extendible members beforepulling the cable and/or actuating the electrically operatable tractionmeans provided on the housing of the drilling device. Where a housing isprovided at the end of the steel tubing remote from the drilling device,this housing is preferably released from the steel tubing and isretrieved from the wellbore prior to expanding the steel tubing.

Where the new wellbore section is a lateral well, the portion of thesteel tubing which passes through the existing wellbore before enteringthe hydrocarbon fluid production conduit may be provided with a valvecomprising a sleeve which is moveable relative to a section of the steeltubing that has a plurality of perforations therein. When the valve isin its closed position the sleeve will cover the perforations in thesection of steel tubing so that produced fluids from the existingwellbore are prevented from entering the hydrocarbon fluid productionconduit. When the sliding sleeve is in its open position the pluralityof perforations are uncovered and produced fluids from the existingwellbore may pass through the perforations into the steel tubing andhence into the hydrocarbon fluid production conduit.

As discussed above, the tubing may also be plastic tubing. Unlike steeltubing, plastic tubing is deformable under the conditions encountereddownhole. Accordingly, the second stream of produced fluid is drawn tothe drilling device through the annulus formed between the plastictubing and the wall of the wellbore and the cuttings stream istransported away from the drilling device through the interior of thetubing (“reverse circulation” mode). Suitably, the second stream ofproduced fluid is drawn to the drilling device via a pumping means, forexample, a suction pump, located in a housing, preferably a cylindricalhousing of the drilling device. The pumping means may be operated asdescribed above. Preferably, the housing of the drilling device isprovided with an electric motor used to actuate a means for rotating adrill bit located at the lower end of the drilling device, for example,the electric motor may actuate a rotor. Preferably, the housing of thedrilling device is provided with an electrically operated tractionmeans, for example, traction wheels or pads which engage with the wallof the new wellbore section and which are used to advance the drillingdevice through the new wellbore section as it is being drilled and totake up the reactive torque generated by the electric motor used todrive the drill bit. Preferably, the entrained cuttings stream is passedto the surface through the hydrocarbon fluid production conduit togetherwith the first stream of produced fluid. It is also envisaged that atleast a portion of the cuttings may be deposited in the rat hole of theexisting wellbore, as described above.

Suitably, the plastic tubing lies within a sandscreen which extendsalong the length of the plastic tubing. The sandscreen may be anexpandable sandscreen or a conventional sandscreen. Typically, thesandscreen is attached to the cable and/or to the drilling device, forexample, via a releasable latch means. Accordingly, once the newwellbore section has been drilled, the sandscreen may be released fromthe cable and/or the drilling device. Where the plastic tubing lieswithin a conventional sandscreen, the drilling device generally has amaximum diameter greater than the inner diameter of the sandscreen. Itis therefore envisaged that the drilling device may be released from thecable and the plastic tubing, for example, via an electronicallyreleasable latch means thereby allowing the cable and plastic tubing tobe pulled from the wellbore through the interior of the conventionalsandscreen and the hydrocarbon fluid production conduit leaving thesandscreen and drilling device in the new wellbore section.Alternatively, the drilling device may be formed from detachable partswherein the individual parts of the drilling device are sized such thatthey may be removed from the wellbore through the interior of theconventional sandscreen. Where the sandscreen is an expandablesandscreen, expansion of the sandscreen may allow the drilling device tobe retrieved from the wellbore through the expanded sandscreen and thehydrocarbon fluid production conduit. It is envisaged that theexpandable sandscreen may be expanded by the steps of:

-   i. locking the drilling device in place in the wellbore, for    example, via radially extendible gripping means, before detaching    the drilling device from the cable;-   ii. releasing the sandscreen from the cable and/or drilling device;-   iii. pulling the cable and associated plastic tubing through the    interior of the sandscreen and through the hydrocarbon fluid    production conduit;-   iv. attaching a conventional tool for expanding a sandscreen to the    cable, for example, an expandable mandrel;-   v. passing the tool, in its unexpanded state, through the    hydrocarbon fluid production conduit and the sandscreen;-   vi. drawing the tool, in its expanded state, back through the    sandscreen to expand the sandscreen;-   vii. retrieving the tool from the wellbore, in its non-expanded    state, by pulling the cable through the hydrocarbon fluid production    conduit;-   viii. retrieving the drilling device from the new section of    wellbore by reinserting the cable, reattaching the drilling device    to the cable, unlocking the drilling device from the wellbore and    pulling the cable and attached drilling device through the expanded    sandscreen and through the production tubing and/or by actuating the    electrically operatable traction means provided on the housing of    the drilling device.

Alternatively, an electrically operated rotatable expansion tool may beattached either directly or indirectly to the drilling device at theupper end thereof. The rotatable expansion tool may also be releasablyattached to the expandable sandscreen, for example, via an electricallyoperated latch means. Electricity is transmitted to the rotatableexpansion tool via an electrical conductor wire or segmented conductorencased in the cable. As discussed above, a suitable rotatable expansiontool is as described in U.S. patent application No. 2001/0045284.Suitably, the rotatable expansion tool may be adapted by providing afluid passage such that, during the drilling operation, the interior ofthe plastic tubing is in fluid communication with a fluid passage in thedrilling device. After completion of drilling of the new wellboresection, the rotatable expansion tool may be released from thesandscreen. The rotatable expansion tool is then operated to expand thesandscreen by drawing the expansion tool and the associated drillingdevice through the sandscreen while simultaneously rotating theexpansion tool and extending the radially extendible members. Followingexpansion of the sandscreen, the plastic tubing, the rotatable expansiontool and the associated drilling device may be retrieved from thewellbore through the hydrocarbon fluid production conduit by retractingthe radially extendible members prior to pulling the cable and/oractuating the electrically operatable traction means provided on thehousing of the drilling device.

It is also envisaged that where the plastic tubing is formed from anelastic material, the plastic tubing may be temporarily sealed at itsend remote from the drilling device. Produced fluid flowing into the newsection of wellbore in the vicinity of the drilling device is thenpumped into the interior of the plastic tubing via the pumping meanslocated in the housing of the drilling device. The plastic tubing isthereby expanded radially outwards owing to the pressure of fluidbuilding up in the temporarily sealed interior of the plastic tubing.Thus, the plastic tubing is capable of expanding the sandscreen againstthe wall of the new wellbore section. Once the sandscreen has beenexpanded, the fluid pressure in the plastic tubing may be relieved byunsealing the end of the plastic tubing remote from the drilling device.The plastic tubing will then contract radially inwards. The drillingdevice may then be removed from the wellbore by pulling the cable andassociated plastic tubing through the expanded sandscreen and thehydrocarbon fluid production conduit and/or by actuating theelectrically operatable traction means provided on the housing of thedrilling device.

In yet a further embodiment of the present invention, the drillingdevice is suspended from tubing having least one electrical conductorwire and/or at least one segmented electrical conductor embedded in thewall thereof (hereinafter “hybrid cable”). Suitably, a passage in thedrilling device is in fluid communication with the interior of thehybrid cable. Preferably, the drilling device is connected to the hybridcable via a releasable connection means.

An advantage of the hybrid cable is that the tubing is provided with atleast one electrical conductor wire and/or at least one segmentedelectrical conductor embedded in the wall thereof for transmittingelectricity and/or electrical signals. A further advantage of the hybridcable is that the second stream of produced fluid may be passed to thedrilling device through the annulus formed between the tubing and thewall of the new section of wellbore and the entrained cuttings streammay be transported away from the drilling device through the interior ofthe tubing (“reverse circulation” mode). Alternatively, the secondstream of produced fluid may be passed to the drilling device throughthe interior of the hybrid cable while the entrained cuttings stream maybe transported away from the drilling device through the annulus formedbetween the hybrid cable and the wall of the new wellbore section(“conventional circulation” mode).

Suitably, the hybrid cable may extend to the surface which has anadvantage of allowing the entrained cuttings stream to be reversecirculated out of the well when the drilling device is operated inreverse circulation mode. Alternatively, the hybrid cable may besuspended from a further cable via a connection means, preferably, areleasable connection means. Suitably, the further cable is aconventional cable or a modified conventional cable of the typedescribed above. The connection means is suitably provided with at leastone electrical connector for connecting the electrical conductor wire(s)or the segmented electrical conductor(s) of the conventional cable ormodified conventional cable with the corresponding electrical conductorwire(s) or segmented electrical conductor(s) of the hybrid cable.Preferably, the hybrid cable has a length that is at least as long asthe desired new wellbore section. Typically, the hybrid cable extendsinto the hydrocarbon fluid production conduit. Suitably, the interior ofthe hybrid cable is in fluid communication with the passage in thedrilling device and with a passage in the connection means.

Preferably, the wall of the hybrid cable is comprised of at least fourlayers. The layers from the inside to the outside of the hybrid cablecomprise: a metal tube suitable for conveying hydrocarbon fluidstherethrough, a flexible insulation layer having the electricalconductor wire(s) and/or segmented electrical conductor(s) embeddedtherein, a fluid barrier layer and a flexible protective sheath.

Preferably, the internal diameter of the inner metal tube of the hybridcable is in the range 0.2 to 5 inches, preferably 0.3 to 1 inches.Preferably, the inner metal tube is formed from steel. Preferably, theflexible insulation layer is comprised of a plastic or rubber material.Preferably, the fluid barrier layer is comprised of steel. Preferably,the flexible protective sheath is comprised of steel braiding. Suitably,the electrical conductor wire(s) and/or segmented electricalconductor(s) embedded in the flexible insulation layer are coated withan electrical insulation material.

Preferably, the drilling device that is connected to the hybrid cablecomprises a housing that is provided with an electrically operatedpumping means, an electric motor for actuating a means for driving adrill bit or mill located at the lower end of the drilling device and anelectrically operated traction means. Optionally, the housing isprovided with an electric motor for actuating a means for driving adrill bit or mill located at the upper end of the drilling device. Asdiscussed above, it is envisaged that a single electric motor mayactuate both of the drive means. Alternatively, each drive means may beprovided with a dedicated electric motor.

Where produced fluid flows from the hydrocarbon fluid bearing zone ofthe formation into the new wellbore section there may be no requirementfor any tubing or for a hybrid cable. Thus, the drilling device maycomprise a housing provided with an electric motor for actuating a meansfor driving a drill bit or mill located on the lower end of the drillingdevice. Optionally, the housing is provided with an electric motor foractuating a means for driving a drill bit or mill located at the upperend of the drilling device. As discussed above, it is envisaged that thehousing may be provided with a single electric motor for actuating bothof the drive means. An electrically operated pumping means, for example,a suction pump, may also be located in the housing of the drillingdevice. The drilling device, suspended on a conventional or modifiedconventional cable, may then be passed to the selected location in theexisting wellbore from which the new wellbore section is to be drilled.As the new wellbore section is being drilled, the pumping means locatedin the housing of the drilling device draws produced fluid flowing fromthe hydrocarbon fluid bearing zone of the reservoir into the newwellbore section through a passage in the drilling device (“secondstream of produced fluid”) and out over the cutting surfaces of thedrill bit or mill. The resulting entrained cuttings stream then flowsaround the outside of the drilling device and is diluted into producedfluid that is flowing to the surface through the production conduit.(“first stream of produced fluid”). Where the new wellbore section is aside-track or lateral wellbore, it is also envisaged that at least aportion of the cuttings may disentrain from the produced fluid and maybe deposited in the rat hole of the existing wellbore, as describedabove.

Where the new wellbore section is a side-track or lateral well and theexisting wellbore is provided with a casing which runs down through theselected located where the new wellbore section is to be drilled, it isgenerally necessary to mill a window through the casing beforecommencing drilling of the new wellbore section. Where the side-track orlateral well is to be drilled from a location in the production conduit,the window is milled through the production conduit and through thecasing before commencing drilling of the new wellbore section. Where thecasing and optionally the production conduit is formed from metal, thismay be achieved by lowering a whipstock to the selected location throughthe hydrocarbon fluid production conduit. Suitably, the whipstock may belowered to the selected location in the wellbore suspended from a cable,for example, a conventional cable or a modified conventional cable, viaa releasable connection means. The whipstock is then locked in place inthe casing or the production conduit via radially extendible grippingmeans, for example radially extendible arms. The whipstock is thenreleased from the cable and the cable is pulled from the wellbore. Afirst drilling device comprising a mill is subsequently lowered to theselected location in the wellbore suspended from a cable, for example, aconventional cable, modified conventional cable or a hybrid cable.However, it is also envisaged that the whipstock may be lowered to theselected location suspended from the first drilling device which, inturn, is suspended from a cable, for example, a conventional cable, amodified conventional cable or a hybrid cable. Suitably, the whipstockmay be suspended from the first drilling device via a releasableconnection means. Once the whipstock is located in the region of thecased wellbore where it is desired to drill the side-track or lateralwell, the whipstock is locked into place in the casing or the productionconduit as described above. The whipstock is then released from thefirst drilling device. By whipstock is meant a device having a planesurface inclined at an angle relative to the longitudinal axis of thewellbore which causes the first drilling device to deflect from theoriginal trajectory of the wellbore at a slight angle so that thecutting surfaces of the mill engage with and mill a window through themetal casing of the wellbore (or through the metal production conduitand the metal casing). Preferably, the first drilling device is providedwith an electrically operated traction means to assist in the millingoperation. Once a window has been milled through the metal casing (orthrough the metal production conduit and the metal casing), the firstdrilling device may be removed from the wellbore by pulling the cableout of the wellbore and/or by operating the traction means. A seconddrilling device comprising a conventional drill bit is then attached tothe cable which is reinserted into the wellbore through the hydrocarbonfluid production conduit. Where the cable is a conventional cable ormodified conventional cable, it is preferred that the cable passesthrough a length of tubing which is in fluid communication with a fluidpassage in the drilling device, as described above. The whipstock causesthe second drilling device to deflect into the window in the casing (orthe window in the production conduit and casing) such that operation ofthe second drilling device results in the drilling of a side-track orlateral well through the hydrocarbon-bearing zone of the formation.However, it is also envisaged that the casing (or the production conduitand casing) at the selected location of the wellbore may be formed froma friable alloy or composite material such that a window may be formedin the casing (or the production conduit and casing) using a drillingdevice comprising a conventional drill bit and the drilling device maythen be used to drill the side-track or lateral well.

Where a whipstock is employed to deflect the drilling device, thewhipstock may remain in the existing wellbore following completion ofdrilling of the new wellbore section. Where the new wellbore is alateral well, the whipstock is provided with a fluid by-pass to allowproduced fluid to continue to flow to the surface from the existingwellbore through the hydrocarbon fluid production conduit. Preferably,the whipstock is retrievable through the production conduit. Thus, thewhipstock may be collapsible, for example, has retractable parts and iscapable of being retrieved through the hydrocarbon fluid productionconduit when in its collapsed state, for example, by attaching a cablethereto and pulling the cable from the wellbore through the hydrocarbonfluid production conduit.

In yet a further embodiment of the present invention there is provided amethod of removing deposits of mineral scale, for example, deposits ofbarium sulfate and/or calcium carbonate from the wall of the existingwellbore, for example, from the wall of the casing of a cased wellborethereby increasing the diameter of the available bore hole. Thus, thedrilling device may be lowered into the wellbore through the hydrocarbonproduction conduit suspended on a conventional cable, a modifiedconventional cable or a hybrid cable to a section of the existingwellbore having mineral scale deposited on the wall thereof. Optionally,the drilling device may be used to remove mineral scale deposits fromthe wall of the production conduit as the drilling device is beinglowered into the wellbore through the production conduit. Suitably, thecuttings of mineral scale are diluted into the first stream of producedfluid that flows from the formation directly to the surface. Preferably,the drilling device that is used to remove mineral scale from the wallof the existing wellbore or from the production conduit is provided withupper and lower cutting surfaces. Thus, a drill bit or mill may belocated on both the upper and lower ends of the drilling device.Preferably, the drill bit or mill that is located on the upper end ofthe device is positioned on the housing below a connector for the cable.By providing a drill bit or mill on the upper end of the device, themineral scale deposit may be removed from the wall of the existingwellbore upon raising the drilling device through the wellbore inaddition to when lowering the device through the wellbore suspended onthe cable. Preferably, an electrically operated traction means isprovided below the upper drill bit or mill to assist in moving thedrilling device upwardly through the wellbore. It is envisaged that thedrilling device may be moved upwardly and downwardly within the wellborea plurality of times, for example, 2 to 5 times, in order tosubstantially remove the mineral scale deposit from the wall of theexisting wellbore, for example, from the wall of the casing of a casedwellbore. Preferably, the drill bit or mill located on the lower end ofthe drilling device and optionally on the upper end of the drillingdevice is an expandable drill bit. This is advantageous when thedrilling device is used to remove mineral scale deposits from the wallof a cased wellbore as the diameter of the wellbore is generallysignificantly larger than the inner diameter of the production conduit.Preferably, the drilling device may also be moved, a plurality of times,upwardly and downwardly within the production conduit in order tosubstantially remove mineral scale deposits from the production conduit.Preferably, the device is left in the wellbore below a producinginterval and is deployed, as required, to remove any mineral scaledeposits that may build up on the wall of the existing wellbore andoptionally on the wall of the production conduit. Suitably, the mineralscale cuttings are removed from the produced fluid at the wellhead,using conventional cuttings separation techniques. However, it is alsoenvisaged that at least a portion of the mineral scale cuttings maydisentrain from the produced fluid and may be deposited in the rat holeof the existing well, as described above.

In yet a further embodiment of the present invention there is provided amethod of removing debris from a perforation tunnel formed in the casingand cement of a cased wellbore or of enlarging such a perforation tunnelusing a remotely controlled electrically operated micro-drilling device.The micro-drilling device comprises a housing provided with anelectrically operated motor for actuating a means for driving a drillbit. The drill bit is mounted on an electrically or hydraulicallyactuated thruster means. Where the thruster means is hydraulicallyactuated, the housing is provided with a reservoir of hydraulic fluid.An electrically operated pumping means is also located within thehousing of the micro-drilling device. Suitably, the motor for actuatingthe means for driving the drill bit has a maximum power of 1 kw. Thedrill bit is sized to form boreholes having a diameter in the range 0.2to 3 inches, preferably, 0.25 to 1 inches. The micro-drilling device issuspended on a cable via a releasable connector and is passed from thesurface through the hydrocarbon fluid production conduit to a selectedlocation is the existing wellbore containing the perforation tunnel fromwhich debris is to be removed or which is to be enlarged. The cable maybe a conventional cable, modified conventional cable or hybrid cable.The micro-drilling device may be orientated adjacent the perforationwith the drill bit aligned with the perforation tunnel, for example, byusing a stepper motor located at the upper end of the micro-drillingdevice. The stepper motor allows the micro-drilling device to rotateabout its longitudinal axis while the connector and cable remainstationary. The micro-drilling device may then be locked in place in thecased wellbore via radially extendible gripping means, for example,hydraulic rams which, when extended, engage with the wall of thewellbore. During the drilling operation, a produced fluid stream ispumped through a first passage in the micro-drilling device and out overthe cutting surfaces of the drill bit via the pumping means. Anentrained cuttings stream is transported away from the cutting surfaces,for example through a second passage in the micro-drilling device. Thethruster means provides a thrusting force to the drill bit such that thedrill bit moves through the perforation tunnel. An advantage of thisfurther embodiment of the present invention is that any produced fluidsflowing from the formation through the perforation tunnel into thewellbore will assist in transporting the drill cuttings out of theperforation tunnel. The micro-drilling device may additionally comprisea mill that is mounted on a thruster means and an electric motor foractuating a means for rotating the mill thereby allowing themicro-drilling device to form a new perforation tunnel at a selectedlocation in the cased wellbore. Suitably, the thruster means provides aforce to the mill so that a perforation is milled through the casing atthe selected location. Suitably the mill is sized such that theperforation has a diameter of 1 to 3 inches. After milling through themetal casing, the drill bit may then be positioned in the perforation tocomplete the perforation tunnel.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic drawing of a remotely controlled electricallyoperated drilling device during drilling.

FIG. 2 is a schematic drawing of a remotely controlled electricallyoperated drilling device during production.

FIG. 3 illustrates a remotely controlled electrically operatedmicro-drilling device according to a preferred aspect of the presentinvention.

FIG. 4 illustrates a transverse cross-section of a modified conventionalcable.

FIG. 5 illustrates a transverse cross-section of a hybrid cable.

The present invention will now be illustrated by reference to FIGS. 1 to5. Referring to FIG. 1, an existing wellbore 1 penetrates through anupper zone 2 of a subterranean formation and into a hydrocarbon-bearingzone 3 of the subterranean formation located below the upper zone 2. Ametal casing 4 is arranged in the existing wellbore 1 and is fixed tothe wellbore wall by a layer of cement 5. A hydrocarbon fluid productionconduit 6 is positioned within the existing wellbore 1 and a packer 7 isprovided at the lower end of the casing 4 to seal the annular spaceformed between the conduit 6 and the casing 4. A wellhead 8 at thesurface provides fluid communication between the conduit 6 and ahydrocarbon fluid production facility (not shown) via a pipe 9. Anexpandable whipstock 10 is passed through the conduit 6 and is locked inplace in the casing 4 of the existing wellbore 1 via radially expandablelocking means 11. A remotely controlled electrically operated drillingdevice 12 is passed into the existing wellbore through the hydrocarbonfluid production conduit 6 suspended on a reinforced steel cable 13comprising at least one electrical conductor wire or segmented conductor(not shown). The lower end of the reinforced steel cable 13 passesthrough a length of steel tubing 14 which is in fluid communication witha fluid passage (not shown) in the drilling device 12. The drillingdevice 12 is provided with an electrically operated steering means, forexample, a steerable joint (not shown) and an electric motor (not shown)arranged to drive a means (not shown) for rotating drill bit 15 locatedat the lower end of the drilling device 12. A cylindrical housing 16 isattached to the upper end of the steel tubing 14. The drilling device 12and/or the housing 16 are provided with an electrically operated pump(not shown) and electrically operated traction wheels or pads 17 whichare used to advance the drilling device 12 through a new wellboresection 18. For avoidance of doubt, the cable 13 passes through thehousing 16 and the interior of the steel tubing 14 to the drillingdevice 12.

The new wellbore section 18 is drilled using the drilling device 12 inthe manner described hereinafter, the new wellbore section extendingfrom a window 19 in the casing 4 of the existing wellbore 1 into thehydrocarbon-bearing zone 3 and being a side-track well or lateral well.The window 19 may have been formed using a drilling device comprising amill which is passed through the production conduit 6 suspended on acable and is then pulled from the existing wellbore. During drilling ofthe new wellbore section 18, produced fluid may be pumped down theinterior of the steel tubing 14 to the drilling device 12 via a pumplocated in the cylindrical housing 16. The produced fluid flows from thesteel tubing 14 through the fluid passage in the drilling device to thedrill bit 15 where the produced fluid serves both to cool the drill bit15 and to entrain drill cuttings. The drill cuttings entrained in theproduced fluid are then passed around the outside of the drilling device12 into the annulus 20 formed between the steel tubing 14 and the wallof the new wellbore section 18 (“conventional circulation” mode).Alternatively, produced fluid may be pumped through the annulus 20 tothe drill bit 15. The drilling cuttings entrained in the produced fluidare then passed through the passage in the drilling device and into theinterior of the steel tubing 14 (“reverse circulation” mode).

A plurality of formation evaluation sensors (not shown) may be located:on the drilling device 12 in close proximity to the drill bit 15; on theend of the steel tubing 14 which is connected to the drilling device 12;along the lower end of the cable 13 that lies within the steel tubing14; or along the outside of the steel tubing. The formation evaluationsensors are electrically connected to recording equipment (not shown) atthe surface via electrical wire(s) and/or segmented conductor(s) whichextend along the length of the cable 13. Where sensors are located onthe outside of the steel tubing, the sensors may be in communicationwith the electrical wire(s) and/or segmented conductor(s) of the cable13 via electromagnetic means. As drilling with the drilling device 12proceeds, the formation evaluation sensors are operated to measureselected formation characteristics and to transmit signals representingthe characteristics via the electrical conductor wire(s) and/orsegmented conductor(s) of the cable 13 to recording equipment at thesurface (not shown).

A navigation system (not shown) for the steering means may also beincluded in the drilling device 12 to assist in navigating the drillingdevice 12 through the new wellbore section 18.

After drilling of the new wellbore section 18, the steel tubing 14 maybe expanded to form a liner for the new wellbore section 18 and thedrilling device 12 may be retrieved by pulling the cable from thewellbore and/or by actuating the traction wheels or pads 17 such thatthe drilling device passes through the expanded steel tubing and thehydrocarbon fluid production conduit 6.

Where the steel tubing is not expandable, the steel tubing may beprovided with at least one radially expandable packer. The packer(s) maybe expanded to seal the annulus formed between the steel tubing 14 andthe new wellbore section 18 thereby forming a sealed liner for the newwellbore section 18. Where a pump is located in the housing of thedrilling device 12, this pump may be disconnected from the housing andmay be retrieved through the interior of the steel tubing 14.

The liner for the new wellbore section is then perforated to allowhydrocarbons to flow through the interior thereof into the productionconduit 6.

Referring to FIG. 2, an existing wellbore 30 penetrates through an upperzone 31 of the subterranean formation into a hydrocarbon-bearing zone 32of the subterranean formation located below the upper zone 31. A metalcasing 33 is arranged in the existing wellbore 30 and is fixed to thewellbore wall by a layer of cement 34. A hydrocarbon fluid productionconduit 35 is positioned within the existing wellbore 30 and is providedat its lower end with a packer 36 which seals the annular space betweenthe conduit 35 and the casing 33. A wellhead 37 at the surface providesfluid communication between the hydrocarbon fluid production conduit 35and a hydrocarbon fluid production facility (not shown) via a pipe 38.An expandable whipstock 39 is passed down the conduit 6 and is locked inplace in the existing wellbore via radially expandable locking means 40.A remotely controlled electrically operated drilling device 41 is passedinto the existing wellbore through the hydrocarbon fluid productionconduit suspended on a reinforced steel cable 42 comprising at least oneelectrical conductor wire or segmented conductor (not shown). The lowerend of the reinforced steel cable 42 passes through a length of plastictubing 43 which is in fluid communication with a fluid passage (notshown) in the drilling device 41. The plastic tubing 43 passes throughan expandable sandscreen 44 which is releasably connected to thedrilling device 41. The drilling device 41 is provided with anelectrically operated pumping means (not shown), an electricallyoperated steering means, for example, a steerable joint (not shown) andan electric motor (not shown) arranged to drive a drill bit 45 locatedat the lower end of the drilling device 41. The drilling device 41 isalso provided with electrically operated traction wheels or pads 46 foradvancing the drilling device 41 though a new wellbore section 47 as itis being drilled or for retrieving the drilling device 41 from thewellbore.

A new wellbore section 47 is drilled using the drilling device 41 in themanner described hereinafter, the new wellbore section extending from awindow 48 in the casing 34 of the existing wellbore 30 into thehydrocarbon-bearing zone 32 and being a side-track well or lateral well.The window may be formed using a drilling device comprising a mill whichis passed through the production conduit suspended on a cable and whichis then retrieved from the existing wellbore by pulling the cable.During drilling of the new wellbore section 47, produced fluid is drawndown the annulus formed between the sandscreen 44 and the wall of thenew wellbore section to the drilling device 41 and the cuttingsentrained in the produced fluid are transported away from the drillingdevice 41 through the interior of the plastic tubing 43.

As discussed above, a plurality of formation evaluation sensors (notshown) may be located: on the drilling device 41 in proximity to thedrill bit 45; on the end of the plastic tubing 43 which is connected tothe drilling device 41; along the cable 42; or on the outside of theplastic tubing 43.

Also, as discussed above, a navigation system (not shown) for thesteering means may be included in the drilling device 41 to assist innavigating the drilling device 41 through the new wellbore section 47.

After drilling of the new wellbore section 47, the sandscreen 44 may beexpanded, for example, by sealing the plastic tubing and pumpingproduced fluid into the interior of the plastic tubing to expand thetubing. The plastic tubing may then be retracted by unsealing thetubing. The drilling device 41 may then be retrieved by pulling thecable 42 and retracted plastic tubing 43 from the wellbore through theexpanded sandscreen 44 and the hydrocarbon fluid production conduit 35and/or by actuating the traction wheels or pads 46.

FIG. 3 illustrates a remotely controlled electrically operatedmicro-drilling device 50 according to a preferred aspect of the presentinvention. The remotely controlled electrically operated micro-drillingdevice 50 is passed into an existing cased wellbore 51 through ahydrocarbon fluid production conduit (not shown) suspended on a cable 52via a connector 53. The cable 52 comprises at least one electricalconductor wire or segmented conductor (not shown) and may be aconventional cable, a modified conventional cable or a hybrid cable ofthe types described above. The micro-drilling device 50 is provided witha mill 54 mounted on a hydraulic piston 55 and a drill bit 56 located atthe end of a flexible rotatable drive tube 57. A pump 58 is in fluidcommunication with the produced fluids in the wellbore via an inlet 59and with the interior of the flexible rotatable drive tube 57. The drivetube 57 is arranged within a telescopic support tube 60 such that anannular space is formed between the drive tube and the support tube. Theconcentrically arranged drive tube 57 and support tube 60 pass through aguide tube 61 thereby orientating the drill bit 56.

During operation of the micro-drilling device, a stepper motor 62 isused to rotate the micro-drilling device 50, about its longitudinalaxis, relative to the connector 53. Once the micro-drilling device 50has been orientated in the wellbore, it is locked in place against thecasing of the wellbore via hydraulic rams 63. The mill is then rotatedvia a first electric drive 64 while hydraulic piston 55 provides athrust force to the mill 54 so that a perforation is milled through thecasing. After the milling operation has been completed, the drill bit 56is aligned with the perforation and the drilling device is locked inplace in the wellbore using the hydraulic rams 63. The drive tube 57 andhence the drill bit 56 is then rotated by means of a second electricdrive 65. During the drilling operation, produced fluid is drawn fromthe wellbore through the inlet 59, via the pump 58, and is passedthrough the interior of the drive tube 57 to the drill bit 56 whilecuttings entrained in the produced fluid are carried away from the drillbit 56 via the annulus formed between the drive tube 57 and thetelescopic support tube 60. A thrust force is provided to the drill bit56 through actuation of further hydraulic rams 66 which drive telescopicsections of the support tube 60 together such that at least one sectionof the support tube slides into another section of the support tube.

FIG. 4 illustrates a transverse cross-section of a modified“conventional cable” comprising a core of an insulation material 70having electrical conductor wires 71 coated with electrical insulationmaterial 72 embedded therein; a fluid barrier layer 73; and steelbraiding 74.

FIG. 5 illustrates a transverse cross-section of a “hybrid cable”comprising an inner metal tube 80 suitable for conveying hydrocarbonfluids through the interior 81 thereof; a flexible insulation layer 82having electrical conductor wires 83 coated with an electricalinsulation material 84 embedded therein; a fluid barrier layer 85; andsteel braiding 86.

1. A method of drilling a borehole from a selected location in an existing wellbore penetrating a subterranean earth formation having at least one hydrocarbon bearing zone wherein the existing wellbore is provided with a casing and a hydrocarbon fluid production conduit is arranged in the existing wellbore in sealing relationship with the wall of the casing, the method comprising: passing a remotely controlled electrically operated drilling device suspended on a cable that encases at least one wire and/or segmented conductor for transmitting electricity or electrical signals, from the surface through the hydrocarbon fluid production conduit to the selected location in the existing wellbore; operating the drilling device such that cutting surfaces on the drilling device drill a new wellbore section from the selected location in the existing wellbore thereby generating drill cuttings wherein at least a lower section of the cable from which the drilling device is suspended lies within a length of tubing having a first end that is in fluid communication with a fluid passage in the drilling device and a second end that extends into the hydrocarbon fluid production conduit and wherein during operation of the drilling device, a first stream of produced fluid flows directly to the surface through the hydrocarbon fluid production conduit and a second stream of produced fluid is pumped over the cutting surfaces of the drilling device via a remotely controlled electrically operated downhole pumping means and the drill cuttings are transported away from the drilling device entrained in the second stream of produced fluid.
 2. A method as claimed in claim 1 wherein the existing wellbore has an upper cased section and a lower uncased section.
 3. A method as claimed in claim 1 wherein the cutting surfaces of the drilling device are located on a drill bit or mill that is provided at or near the lower end of the drilling device and optionally on a drill bit or mill that is provided at or near the upper end of the drilling device.
 4. A method as claimed in claim 3 wherein the drill bit or mill is expandable thereby allowing the borehole that is drilled from the selected location to be of a larger diameter than the inner diameter of the production conduit.
 5. A method as claimed in claim 3 wherein the drilling device is provided with an electrically operated steering means for the drill bit or mill.
 6. A method as claimed in claim 3 wherein the drilling device is provided with an electric motor for actuating a means for driving the drill bit or mill.
 7. A method as claimed in claim 1 wherein the drilling device is provided with the electrically operated pumping means.
 8. A method as claimed in claim 1 wherein the drilling device is provided with an electrically operated traction means.
 9. A method as claimed in claim 1 wherein the borehole that is drilled from the selected location is (a) a new section of wellbore; (b) a window in the casing of the existing wellbore or a window in the production conduit and casing of the existing wellbore; (c) a perforation tunnel in the casing and cement of the existing wellbore; or (d) an enlarged borehole through at least a section of the existing wellbore having mineral scale deposited on the wall thereof.
 10. A method as claimed in claim 9 for drilling a side-track or lateral well comprising: passing a whipstock having radially extendable gripping means from the surface through the hydrocarbon fluid production conduit to the selected location in the casing or production conduit of the existing wellbore; locking the whipstock into place either in the casing of the existing wellbore or in the production conduit by radially extending the gripping means; lowering a first drilling device comprising a mill suspended from a cable, through the hydrocarbon production conduit to the selected location; deflecting the first drilling device against the whipstock such that the cutting surfaces of the mill engage with the casing or production conduit; operating the first drilling device such that a window is milled through the casing of the wellbore or through the production conduit and casing of the wellbore; removing the first drilling device from the wellbore; lowering a second drilling device comprising a drill bit, suspended from a cable, through the hydrocarbon fluid production conduit to the selected location; deflecting the second drilling device against the whipstock into the window in the casing or the window in the production conduit and casing; and operating the second drilling device such that the culling surfaces of the drill bit drill a side-track or lateral well through the hydrocarbon-bearing zone of the formation.
 11. A method as claimed in claim 10 wherein the whipstock is passed to the selected location suspended from the first drilling device.
 12. A method as claimed in claim 1 wherein the drilling device is suspended from the cable via a releasable connection means.
 13. A method as claimed in claim 1 wherein the tubing is steel tubing or plastic tubing.
 14. A method as claimed in claim 13 wherein the second stream of produced fluid is passed to the drilling device through the annulus formed between the tubing and the wall-of the new section of wellbore and the entrained cuttings stream is transported away from the drilling device through the interior of the tubing.
 15. A method as claimed in claim 13 wherein the tubing is steel tubing and the second stream of produced fluid is passed to the drilling device through the interior of the steel tubing and the entrained cuttings stream is transported away from the drilling device through the annulus formed between the steel tubing and die wall of the new section of wellbore (“conventional circulation” mode).
 16. A method as claimed in claim 13 wherein the steel tubing is provided with at least one radially expandable packer and after completion of drilling of the new wellbore section, the steel tubing is locked in place in the new wellbore section by expanding the at least one radially expandable packer so that the steel tubing forms a sealed liner for the new wellbore section.
 17. A method as claimed in claim 16 wherein the steel tubing is subsequently perforated to allow fluid to flow from the hydrocarbon-bearing zone of the formation into the interior of the liner and into the hydrocarbon fluid production conduit.
 18. A method as claimed in claim 13 wherein the steel tubing is expandable tubing and is capable of being passed through the hydrocarbon fluid production conduit in its non-expanded state after completion of the drilling of the new welibore section, is capable of being expanded to form a liner for the new wellbore section.
 19. A method as claimed in claim 1 wherein the drilling device is provided with an electrically operated traction means to advance the drilling device and tubing through the new wellbore section as it is being drilled and/or to withdraw the drilling device from the new wellbore section and existing wellbore after completion of the drilling of the new wellbore section.
 20. A method as claimed in claim 1 wherein the tubing is steel tubing and a housing is attached either directly or indirectly to the second end of the steel tubing and the interior of the steel tubing is in fluid communication with a passage in the housing.
 21. A method as claimed in claim 20 wherein the maximum outer diameter of the housing is less than the inner diameter of the production conduit.
 22. A method as claimed in claims 20 wherein the housing attached to the second end of the steel tubing is provided with an electrically operated pumping means either for passing the second stream of produced hydrocarbon through the interior of the steel tubing to the drilling device or for drawing the entrained cuttings stream away from the drilling device through the interior of the steel tubing.
 23. A method as claimed in claim 20 wherein the housing attached to the second end of the steel tubing is provided with electric motor for actuating a means for rotating the steel tubing thereby rotating the drilling device so that the culling surfaces on the drilling device drill the new section of wellbore.
 24. A method as claimed in claims 20 wherein the housing attached to the second end of the steel tubing is provided with an electrically operated traction means for advancing the steel tubing and hence the drilling device through the new wellbore section as it is being drilled and optionally for withdrawing the steel tubing and hence the drilling device from the new wellbore section.
 25. A method as claimed in claim 1 wherein sensors are provided along the cable and along the outside of the tubing for transmitting data to the surface via the electrical conductor wire(s) and/or segmented electrical conductor(s) encased in the cable. 